10-K 1 xom10k2017.htm FORM 10-K  

 

 

2017

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-K

    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2017

or

    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                to               

Commission File Number 1-2256

EXXON MOBIL CORPORATION

(Exact name of registrant as specified in its charter)

 

 

 

NEW JERSEY

13-5409005

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification Number)

5959 LAS COLINAS BOULEVARD, IRVING, TEXAS 75039-2298

(Address of principal executive offices) (Zip Code)

(972) 940-6000

(Registrant’s telephone number, including area code)

 

Securities registered pursuant to Section 12(b) of the Act:

 

 

 

Title of Each Class

Name of Each Exchange

on Which Registered

Common Stock, without par value (4,237,462,159 shares outstanding at January 31, 2018)

New York Stock  Exchange

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes       No  

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes     No    

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes       No    

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes       No  

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or emerging growth company.  See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer

Accelerated filer

 

Non-accelerated filer

Smaller reporting company

 

 

Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act).    Yes      No    

The aggregate market value of the voting stock held by non-affiliates of the registrant on June 30, 2017, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $80.73 on the New York Stock Exchange composite tape, was in excess of $342 billion.

Documents Incorporated by Reference:  Proxy Statement for the 2018 Annual Meeting of Shareholders (Part III)

 

 

 

 


 

   

EXXON MOBIL CORPORATION

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2017

TABLE OF CONTENTS

 

 

 

PART I

 

 

 

Item 1.

Business

           1 

 

 

 

Item 1A.

Risk Factors

           2 

 

 

 

Item 1B.

Unresolved Staff Comments

           4 

 

 

 

Item 2.

Properties

           5 

 

 

 

Item 3.

Legal Proceedings

         26 

 

 

 

Item 4.

Mine Safety Disclosures

         26 

 

 

Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)]

         27 

 

PART II

 

 

 

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

         30 

 

 

 

Item 6.

Selected Financial Data

         30 

 

 

 

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

         30 

 

 

 

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

         31 

 

 

 

Item 8.

Financial Statements and Supplementary Data

         31 

 

 

 

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

         31 

 

 

 

Item 9A.

Controls and Procedures

         31 

 

 

 

Item 9B.

Other Information

         31 

 

PART III

 

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

         32  

 

 

 

Item 11.

Executive Compensation

         32  

 

 

 

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

         32  

 

 

 

Item 13.

Certain Relationships and Related Transactions, and Director Independence

         33  

 

 

 

Item 14.

Principal Accounting Fees and Services

         33  

 

PART IV

 

 

 

Item 15.

Exhibits, Financial Statement Schedules

         33  

 

 

 

Item 16.

Form 10-K Summary

         33  

 

 

Financial Section

         34  

 

 

Index to Exhibits

      120  

 

 

Signatures

      121  

 

 

Exhibit 12 — Computation of Ratio of Earnings to Fixed Charges

 

 

 

Exhibit 18 — Preferability Letter

 

 

 

Exhibits 31 and 32 — Certifications

 

 


 

   

PART I

ITEM 1.       BUSINESS

Exxon Mobil Corporation was incorporated in the State of New Jersey in 1882. Divisions and affiliated companies of ExxonMobil operate or market products in the United States and most other countries of the world. Their principal business is energy, involving exploration for, and production of, crude oil and natural gas, manufacture of petroleum products and transportation and sale of crude oil, natural gas and petroleum products. ExxonMobil is a major manufacturer and marketer of commodity petrochemicals, including olefins, aromatics, polyethylene and polypropylene plastics and a wide variety of specialty products. Affiliates of ExxonMobil conduct extensive research programs in support of these businesses.

Exxon Mobil Corporation has several divisions and hundreds of affiliates, many with names that include ExxonMobil, Exxon, Esso, Mobil or XTO. For convenience and simplicity, in this report the terms ExxonMobil, Exxon, Esso, Mobil and XTO, as well as terms like Corporation, Company, our, we  and its, are sometimes used as abbreviated references to specific affiliates or groups of affiliates. The precise meaning depends on the context in question.

The energy and petrochemical industries are highly competitive. There is competition within the industries and also with other industries in supplying the energy, fuel and chemical needs of both industrial and individual consumers. The Corporation competes with other firms in the sale or purchase of needed goods and services in many national and international markets and employs all methods of competition which are lawful and appropriate for such purposes.

Operating data and industry segment information for the Corporation are contained in the Financial Section of this report under the following: “Quarterly Information”, “Note 18: Disclosures about Segments and Related Information” and “Operating Information”. Information on oil and gas reserves is contained in the “Oil and Gas Reserves” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion of the Financial Section of this report.

ExxonMobil has a long‑standing commitment to the development of proprietary technology. We have a wide array of research programs designed to meet the needs identified in each of our business segments. Information on Company‑sponsored research and development spending is contained in “Note 3: Miscellaneous Financial Information” of the Financial Section of this report. ExxonMobil held over 12 thousand active patents worldwide at the end of 2017. For technology licensed to third parties, revenues totaled approximately $89 million in 2017. Although technology is an important contributor to the overall operations and results of our Company, the profitability of each business segment is not dependent on any individual patent, trade secret, trademark, license, franchise or concession.

The number of regular employees was 69.6 thousand, 71.1 thousand, and 73.5 thousand at years ended 2017, 2016 and 2015, respectively. Regular employees are defined as active executive, management, professional, technical and wage employees who work full time or part time for the Corporation and are covered by the Corporation’s benefit plans and programs. Regular employees do not include employees of the company‑operated retail sites (CORS). The number of CORS employees was 1.6 thousand, 1.6 thousand, and 2.1 thousand at years ended 2017, 2016 and 2015, respectively.

Throughout ExxonMobil’s businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on air, water and ground. These include a significant investment in refining infrastructure and technology to manufacture clean fuels, as well as projects to monitor and reduce nitrogen oxide, sulfur oxide and greenhouse gas emissions, and expenditures for asset retirement obligations. Using definitions and guidelines established by the American Petroleum Institute, ExxonMobil’s 2017 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were $4.7 billion, of which $3.3 billion were included in expenses with the remainder in capital expenditures. The total cost for such activities is expected to increase to approximately $5 billion in 2018 and 2019. Capital expenditures are expected to account for approximately 30 percent of the total.

Information concerning the source and availability of raw materials used in the Corporation’s business, the extent of seasonality in the business, the possibility of renegotiation of profits or termination of contracts at the election of governments and risks attendant to foreign operations may be found in “Item 1A. Risk Factors” and “Item 2. Properties” in this report.

ExxonMobil maintains a website at exxonmobil.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) of the Securities Exchange Act of 1934 are made available through our website as soon as reasonably practical after we electronically file or furnish the reports to the Securities and Exchange Commission (SEC). Also available on the Corporation’s website are the Company’s Corporate Governance Guidelines and Code of Ethics and Business Conduct, as well as the charters of the audit, compensation and nominating committees of the Board of Directors. Information on our website is not incorporated into this report.

1 


 

ITEM 1A.       RISK FACTORS

ExxonMobil’s financial and operating results are subject to a variety of risks inherent in the global oil, gas, and petrochemical businesses. Many of these risk factors are not within the Company’s control and could adversely affect our business, our financial and operating results, or our financial condition. These risk factors include:

 

Supply and Demand

The oil, gas, and petrochemical businesses are fundamentally commodity businesses. This means ExxonMobil’s operations and earnings may be significantly affected by changes in oil, gas, and petrochemical prices and by changes in margins on refined products. Oil, gas, petrochemical, and product prices and margins in turn depend on local, regional, and global events or conditions that affect supply and demand for the relevant commodity. Any material decline in oil or natural gas prices could have a material adverse effect on certain of the Company’s operations, especially in the Upstream segment, financial condition, and proved reserves. On the other hand, a material increase in oil or natural gas prices could have a material adverse effect on certain of the Company’s operations, especially in the Downstream and Chemical segments.

Economic conditions. The demand for energy and petrochemicals is generally linked closely with broad-based economic activities and levels of prosperity. The occurrence of recessions or other periods of low or negative economic growth will typically have a direct adverse impact on our results. Other factors that affect general economic conditions in the world or in a major region, such as changes in population growth rates, periods of civil unrest, government austerity programs, or currency exchange rate fluctuations, can also impact the demand for energy and petrochemicals. Sovereign debt downgrades, defaults, inability to access debt markets due to credit or legal constraints, liquidity crises, the breakup or restructuring of fiscal, monetary, or political systems such as the European Union, and other events or conditions that impair the functioning of financial markets and institutions also pose risks to ExxonMobil, including risks to the safety of our financial assets and to the ability of our partners and customers to fulfill their commitments to ExxonMobil.

Other demand-related factors. Other factors that may affect the demand for oil, gas, and petrochemicals, and therefore impact our results, include technological improvements in energy efficiency; seasonal weather patterns, which affect the demand for energy associated with heating and cooling; increased competitiveness of alternative energy sources that have so far generally not been competitive with oil and gas without the benefit of government subsidies or mandates; changes in technology or consumer preferences that alter fuel choices, such as technological advances in energy storage that make wind and solar more competitive for power generation or increased consumer demand for alternative fueled or electric vehicles; and broad-based changes in personal income levels.

Other supply-related factors. Commodity prices and margins also vary depending on a number of factors affecting supply. For example, increased supply from the development of new oil and gas supply sources and technologies to enhance recovery from existing sources tend to reduce commodity prices to the extent such supply increases are not offset by commensurate growth in demand. Similarly, increases in industry refining or petrochemical manufacturing capacity relative to demand tend to reduce margins on the affected products. World oil, gas, and petrochemical supply levels can also be affected by factors that reduce available supplies, such as adherence by member countries to OPEC production quotas and the occurrence of wars, hostile actions, natural disasters, disruptions in competitors’ operations, or unexpected unavailability of distribution channels that may disrupt supplies. Technological change can also alter the relative costs for competitors to find, produce, and refine oil and gas and to manufacture petrochemicals.

Other market factors. ExxonMobil’s business results are also exposed to potential negative impacts due to changes in interest rates, inflation, currency exchange rates, and other local or regional market conditions.

 

Government and Political Factors

ExxonMobil’s results can be adversely affected by political or regulatory developments affecting our operations.

Access limitations. A number of countries limit access to their oil and gas resources, or may place resources off-limits from development altogether. Restrictions on foreign investment in the oil and gas sector tend to increase in times of high commodity prices, when national governments may have less need of outside sources of private capital. Many countries also restrict the import or export of certain products based on point of origin.

Restrictions on doing business. ExxonMobil is subject to laws and sanctions imposed by the United States or by other jurisdictions where we do business that may prohibit ExxonMobil or certain of its affiliates from doing business in certain countries, or restricting the kind of business that may be conducted. Such restrictions may provide a competitive advantage to competitors who may not be subject to comparable restrictions.

Lack of legal certainty. Some countries in which we do business lack well-developed legal systems, or have not yet adopted, or may be unable to maintain, clear regulatory frameworks for oil and gas development. Lack of legal certainty exposes our operations to increased risk of adverse or unpredictable actions by government officials, and also makes it more difficult for us to enforce our contracts. In some cases these risks can be partially offset by agreements to arbitrate disputes in an international forum, but the adequacy of this remedy may still depend on the local legal system to enforce an award.

2 


 

Regulatory and litigation risks. Even in countries with well-developed legal systems where ExxonMobil does business, we remain exposed to changes in law (including changes that result from international treaties and accords) that could adversely affect our results, such as:

  

·           

increases in taxes, duties, or government royalty rates (including retroactive claims);

·           

price controls;

·           

changes in environmental regulations or other laws that increase our cost of compliance or reduce or delay available business opportunities (including changes in laws related to offshore drilling operations, water use, methane emissions, or hydraulic fracturing);

·           

adoption of regulations mandating efficiency standards, the use of alternative fuels or uncompetitive fuel components;

·           

adoption of government payment transparency regulations that could require us to disclose competitively sensitive commercial information, or that could cause us to violate the non-disclosure laws of other countries; and

·           

government actions to cancel contracts, re-denominate the official currency, renounce or default on obligations, renegotiate terms unilaterally, or expropriate assets.

Legal remedies available to compensate us for expropriation or other takings may be inadequate.

We also may be adversely affected by the outcome of litigation, especially in countries such as the United States in which very large and unpredictable punitive damage awards may occur, or by government enforcement proceedings alleging non-compliance with applicable laws or regulations.

Security concerns. Successful operation of particular facilities or projects may be disrupted by civil unrest, acts of sabotage or terrorism, cybersecurity attacks, and other local security concerns. Such concerns may require us to incur greater costs for security or to shut down operations for a period of time.

Climate change and greenhouse gas restrictions. Due to concern over the risks of climate change, a number of countries have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions. These include adoption of cap and trade regimes, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates for renewable energy. These requirements could make our products more expensive, lengthen project implementation times, and reduce demand for hydrocarbons, as well as shift hydrocarbon demand toward relatively lower-carbon sources such as natural gas. Current and pending greenhouse gas regulations or policies may also increase our compliance costs, such as for monitoring or sequestering emissions.

Government sponsorship of alternative energy. Many governments are providing tax advantages and other subsidies to support alternative energy sources or are mandating the use of specific fuels or technologies. Governments and others are also promoting research into new technologies to reduce the cost and increase the scalability of alternative energy sources. We are conducting our own research both in-house and by working with more than 80 leading universities around the world, including the Massachusetts Institute of Technology, Princeton University, the University of Texas, and Stanford University. Our research projects focus on developing algae-based biofuels, carbon capture and storage, breakthrough energy efficiency processes, advanced energy-saving materials, and other technologies. For example, ExxonMobil is working with Fuel Cell Energy Inc. to explore using carbonate fuel cells to economically capture CO2 emissions from gas-fired power plants. Our future results may depend in part on the success of our research efforts and on our ability to adapt and apply the strengths of our current business model to providing the energy products of the future in a cost-competitive manner. See “Operational and Other Factors” below.

 

Operational and Other Factors

In addition to external economic and political factors, our future business results also depend on our ability to manage successfully those factors that are at least in part within our control. The extent to which we manage these factors will impact our performance relative to competition. For projects in which we are not the operator, we depend on the management effectiveness of one or more co-venturers whom we do not control.

Exploration and development program. Our ability to maintain and grow our oil and gas production depends on the success of our exploration and development efforts. Among other factors, we must continuously improve our ability to identify the most promising resource prospects and apply our project management expertise to bring discovered resources on line as scheduled and within budget.

Project and portfolio management. The long-term success of ExxonMobil’s Upstream, Downstream, and Chemical businesses depends on complex, long‑term, capital intensive projects. These projects in turn require a high degree of project management expertise to maximize efficiency. Specific factors that can affect the performance of major projects include our ability to: negotiate successfully with joint venturers, partners, governments, suppliers, customers, or others; model and optimize reservoir performance; develop markets for project outputs, whether through long-term contracts or the development of effective spot markets; manage changes in operating conditions and costs, including costs of third party equipment or services such as drilling rigs and shipping; prevent, to the extent possible, and respond effectively to unforeseen technical difficulties that could delay project startup or cause unscheduled project downtime; and influence the performance of project operators where ExxonMobil does not perform that role. In addition to the effective management of individual projects, ExxonMobil’s success, including our ability to mitigate risk and

3 


 

provide attractive returns to shareholders, depends on our ability to successfully manage our overall portfolio, including diversification among types and locations of our projects.

The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports.

Operational efficiency. An important component of ExxonMobil’s competitive performance, especially given the commodity‑based nature of many of our businesses, is our ability to operate efficiently, including our ability to manage expenses and improve production yields on an ongoing basis. This requires continuous management focus, including technology improvements, cost control, productivity enhancements, regular reappraisal of our asset portfolio, and the recruitment, development, and retention of high caliber employees.

Research and development. To maintain our competitive position, especially in light of the technological nature of our businesses and the need for continuous efficiency improvement, ExxonMobil’s research and development organizations must be successful and able to adapt to a changing market and policy environment, including developing technologies to help reduce greenhouse gas emissions.

Safety, business controls, and environmental risk management. Our results depend on management’s ability to minimize the inherent risks of oil, gas, and petrochemical operations, to control effectively our business activities, and to minimize the potential for human error. We apply rigorous management systems and continuous focus to workplace safety and to avoiding spills or other adverse environmental events. For example, we work to minimize spills through a combined program of effective operations integrity management, ongoing upgrades, key equipment replacements, and comprehensive inspection and surveillance. Similarly, we are implementing cost-effective new technologies and adopting new operating practices to reduce air emissions, not only in response to government requirements but also to address community priorities. We also maintain a disciplined framework of internal controls and apply a controls management system for monitoring compliance with this framework. Substantial liabilities and other adverse impacts could result if our management systems and controls do not function as intended.

Cybersecurity. ExxonMobil is regularly subject to attempted cybersecurity disruptions from a variety of threat actors. If our systems for protecting against cybersecurity disruptions prove to be insufficient, ExxonMobil as well as our customers, employees, or third parties could be adversely affected. Such cybersecurity disruptions could cause physical harm to people or the environment; damage or destroy assets; compromise business systems; result in proprietary information being altered, lost, or stolen; result in employee, customer, or third-party information being compromised; or otherwise disrupt our business operations. We could incur significant costs to remedy the effects of such a cybersecurity disruption as well as in connection with resulting regulatory actions and litigation.

Preparedness. Our operations may be disrupted by severe weather events, natural disasters, human error, and similar events. For example, hurricanes may damage our offshore production facilities or coastal refining and petrochemical plants in vulnerable areas. Our facilities are designed, constructed, and operated to withstand a variety of extreme climatic and other conditions, with safety factors built in to cover a number of engineering uncertainties, including those associated with wave, wind, and current intensity, marine ice flow patterns, permafrost stability, storm surge magnitude, temperature extremes, extreme rain fall events, and earthquakes. Our consideration of changing weather conditions and inclusion of safety factors in design covers the engineering uncertainties that climate change and other events may potentially introduce. Our ability to mitigate the adverse impacts of these events depends in part upon the effectiveness of our robust facility engineering as well as our rigorous disaster preparedness and response and business continuity planning.

Insurance limitations. The ability of the Corporation to insure against many of the risks it faces as described in this Item 1A is limited by the capacity of the applicable insurance markets, which may not be sufficient.

Competition. As noted in Item 1 above, the energy and petrochemical industries are highly competitive. We face competition not only from other private firms, but also from state-owned companies that are increasingly competing for opportunities outside of their home countries. In some cases, these state-owned companies may pursue opportunities in furtherance of strategic objectives of their government owners, with less focus on financial returns than companies owned by private shareholders, such as ExxonMobil. Technology and expertise provided by industry service companies may also enhance the competitiveness of firms that may not have the internal resources and capabilities of ExxonMobil.

Reputation. Our reputation is an important corporate asset. An operating incident, significant cybersecurity disruption, or other adverse event such as those described in this Item 1A may have a negative impact on our reputation, which in turn could make it more difficult for us to compete successfully for new opportunities, obtain necessary regulatory approvals, or could reduce consumer demand for our branded products.

Projections, estimates, and descriptions of ExxonMobil’s plans and objectives included or incorporated in Items 1, 1A, 2, 7 and 7A of this report are forward-looking statements. Actual future results, including project completion dates, production rates, capital expenditures, costs, and business plans could differ materially due to, among other things, the factors discussed above and elsewhere in this report.

ITEM 1B.        UNRESOLVED STAFF COMMENTS

None.

4 


 

Item 2.       Properties

Information with regard to oil and gas producing activities follows:

 

1. Disclosure of Reserves

A. Summary of Oil and Gas Reserves at Year-End 2017

The table below summarizes the oil-equivalent proved reserves in each geographic area and by product type for consolidated subsidiaries and equity companies. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. The Corporation has reported proved reserves on the basis of the average of the first-day-of-the-month price for each month during the last 12-month period. No major discovery or other favorable or adverse event has occurred since December 31, 2017, that would cause a significant change in the estimated proved reserves as of that date.

 

 

 

 

 

 

Crude

Natural Gas

 

Synthetic

Natural

Oil-Equivalent

 

 

 

 

 

Oil

Liquids

Bitumen

Oil

Gas

Basis

 

 

 

 

 

(million bbls)

(million bbls)

(million bbls)

(million bbls)

(billion cubic ft)

(million bbls)

Proved Reserves

 

 

 

 

 

 

 

Developed

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

United States

1,137

352

-

-

12,649

3,597

 

 

 

Canada/Other Americas (1) 

85

7

657

473

512

1,307

 

 

 

Europe

93

26

-

-

1,231

325

 

 

 

Africa

593

83

-

-

584

773

 

 

 

Asia

2,070

112

-

-

4,030

2,854

 

 

 

Australia/Oceania

85

46

-

-

4,420

868

 

 

 

 

Total Consolidated

4,063

626

657

473

23,426

9,724

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

201

7

-

-

154

234

 

 

 

Europe

14

-

-

-

4,899

830

 

 

 

Africa

-

-

-

-

-

-

 

 

 

Asia

715

304

-

-

12,898

3,168

 

 

 

 

Total Equity Company

930

311

-

-

17,951

4,232

 

 

 

 

Total Developed

4,993

937

657

473

41,377

13,956

 

 

 

 

 

 

 

 

 

 

 

 

Undeveloped

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

United States

1,558

609

-

-

6,384

3,231

 

 

 

Canada/Other Americas (1) 

325

12

355

-

860

835

 

 

 

Europe

26

4

-

-

137

53

 

 

 

Africa

136

1

-

-

11

139

 

 

 

Asia

1,426

-

-

-

310

1,478

 

 

 

Australia/Oceania

25

6

-

-

2,474

443

 

 

 

 

Total Consolidated

3,496

632

355

-

10,176

6,179

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

44

4

-

-

69

60

 

 

 

Europe

1

-

-

-

1,265

212

 

 

 

Africa

6

-

-

-

914

158

 

 

 

Asia

382

49

-

-

1,350

656

 

 

 

 

Total Equity Company

433

53

-

-

3,598

1,086

 

 

 

 

Total Undeveloped

3,929

685

355

-

13,774

7,265

Total Proved Reserves

8,922

1,622

1,012

473

55,151

21,221

 

(1)   Other Americas includes proved developed reserves of 2 million barrels of crude oil and 42 billion cubic feet of natural gas, as well as proved undeveloped reserves of 150 million barrels of crude oil and 175 billion cubic feet of natural gas.

5 


 

   

In the preceding reserves information, consolidated subsidiary and equity company reserves are reported separately. However, the Corporation operates its business with the same view of equity company reserves as it has for reserves from consolidated subsidiaries.

The Corporation anticipates several projects will come online over the next few years providing additional production capacity. However, actual volumes will vary from year to year due to the timing of individual project start-ups; operational outages; reservoir performance; performance of enhanced oil recovery projects; regulatory changes; the impact of fiscal and commercial terms; asset sales; weather events; price effects on production sharing contracts; changes in the amount and timing of capital investments that may vary depending on the oil and gas price environment; and other factors described in Item 1A. Risk Factors.

The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessments and detailed analysis of well and reservoir information such as flow rates and reservoir pressures. Furthermore, the Corporation only records proved reserves for projects which have received significant funding commitments by management made toward the development of the reserves. Although the Corporation is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals, government policies, consumer preferences, and significant changes in long-term oil and natural gas price levels. In addition, proved reserves could be affected by an extended period of low prices which could reduce the level of the Corporation’s capital spending and also impact our partners’ capacity to fund their share of joint projects.

B. Technologies Used in Establishing Proved Reserves Additions in 2017

Additions to ExxonMobil’s proved reserves in 2017 were based on estimates generated through the integration of available and appropriate geological, engineering and production data, utilizing well-established technologies that have been demonstrated in the field to yield repeatable and consistent results.

Data used in these integrated assessments included information obtained directly from the subsurface via wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements including high-quality 3-D and 4-D seismic data, calibrated with available well control information. The tools used to interpret the data included proprietary seismic processing software, proprietary reservoir modeling and simulation software, and commercially available data analysis packages.

In some circumstances, where appropriate analog reservoirs were available, reservoir parameters from these analogs were used to increase the quality of and confidence in the reserves estimates.

C. Qualifications of Reserves Technical Oversight Group and Internal Controls over Proved Reserves

ExxonMobil has a dedicated Global Reserves group that provides technical oversight and is separate from the operating organization. Primary responsibilities of this group include oversight of the reserves estimation process for compliance with Securities and Exchange Commission (SEC) rules and regulations, review of annual changes in reserves estimates, and the reporting of ExxonMobil’s proved reserves. This group also maintains the official company reserves estimates for ExxonMobil’s proved reserves of crude oil, natural gas liquids, bitumen, synthetic oil, and natural gas. In addition, the group provides training to personnel involved in the reserves estimation and reporting process within ExxonMobil and its affiliates. The Manager of the Global Reserves group has more than 25 years of experience in reservoir engineering and reserves assessment and has a degree in Engineering. He is an active member of the Society of Petroleum Engineers (SPE). The group is staffed with individuals that have an average of more than 20 years of technical experience in the petroleum industry, including expertise in the classification and categorization of reserves under the SEC guidelines. This group includes individuals who hold advanced degrees in either Engineering or Geology, and a member currently serves on the SPE Oil and Gas Reserves Committee.

The Global Reserves group maintains a central database containing the official company reserves estimates. Appropriate controls, including limitations on database access and update capabilities, are in place to ensure data integrity within this central database. An annual review of the system’s controls is performed by internal audit. Key components of the reserves estimation process include technical evaluations and analysis of well and field performance and a rigorous peer review. No changes may be made to the reserves estimates in the central database, including additions of any new initial reserves estimates or subsequent revisions, unless these changes have been thoroughly reviewed and evaluated by duly authorized personnel within the operating organization. In addition, changes to reserves estimates that exceed certain thresholds require further review and approval of the appropriate level of management within the operating organization before the changes may be made in the central database. Endorsement by the Global Reserves group for all proved reserves changes is a mandatory component of this review process. After all changes are made, reviews are held with senior management for final endorsement.

6 


 

 2. Proved Undeveloped Reserves

At year-end 2017, approximately 7.3 billion oil-equivalent barrels (GOEB) of ExxonMobil’s proved reserves were classified as proved undeveloped. This represents 34 percent of the 21.2 GOEB reported in proved reserves. This compares to the 6.2 GOEB of proved undeveloped reserves reported at the end of 2016. During the year, ExxonMobil conducted development activities that resulted in the transfer of approximately 0.7 GOEB from proved undeveloped to proved developed reserves by year‑end. The largest transfers were related to the start-up of the Gorgon field and Longford Gas Conditioning Plant in Australia and drilling activity in the United States, the United Arab Emirates, and Kazakhstan. During 2017, extensions and discoveries, primarily in the United Arab Emirates, the United States, and Guyana resulted in an addition of approximately 0.9 GOEB of proved undeveloped reserves. Also, purchases, primarily in the United States and Mozambique resulted in the addition of approximately 0.9 GOEB of proved undeveloped reserves.

Overall, investments of $8 billion were made by the Corporation during 2017 to progress the development of reported proved undeveloped reserves, including $8 billion for oil and gas producing activities and in addition, nearly $100 million for other non-oil and gas producing activities such as the construction of support infrastructure and other related facilities. These investments represented 48 percent of the $16.7 billion in total reported Upstream capital and exploration expenditures. Investments made by the Corporation to develop quantities which no longer meet the SEC definition of proved reserves due to 2017 average prices are included in the $16.7 billion of Upstream capital expenditures reported above but are excluded from amounts related to progressing the development of proved undeveloped reserves.

One of ExxonMobil’s requirements for reporting proved reserves is that management has made significant funding commitments toward the development of the reserves. ExxonMobil has a disciplined investment strategy and many major fields require long lead‑time in order to be developed. Development projects typically take several years from the time of recording proved undeveloped reserves to the start of production and can exceed five years for large and complex projects. Proved undeveloped reserves in Canada, Kazakhstan, Australia, the Netherlands, the United States, and Qatar have remained undeveloped for five years or more primarily due to constraints on the capacity of infrastructure, as well as the time required to complete development for very large projects. The Corporation is reasonably certain that these proved reserves will be produced; however, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals, government policies, consumer preferences, the pace of co‑venturer/government funding, and significant changes in long-term oil and natural gas price levels. Of the proved undeveloped reserves that have been reported for five or more years, over 80 percent are contained in the aforementioned countries. In Canada, proved undeveloped reserves are related to drilling activities in the offshore Hebron field and onshore Cold Lake operations. In Kazakhstan, the proved undeveloped reserves are related to the remainder of the initial development of the producing offshore Kashagan field which is included in the North Caspian Production Sharing Agreement and the Tengizchevroil joint venture which includes a production license in the Tengiz – Korolev field complex. The Tengizchevroil joint venture is producing, and proved undeveloped reserves will continue to move to proved developed as approved development phases progress. In Australia, proved undeveloped reserves are associated with future compression for the Gorgon Jansz LNG project. In the Netherlands, the Groningen gas field has proved undeveloped reserves related to installation of future compression.

7 


 

3. Oil and Gas Production, Production Prices and Production Costs

A. Oil and Gas Production

The table below summarizes production by final product sold and by geographic area for the last three years.



 

 

 

 

 

 

2017

 

2016

 

2015

 

 

 

 

 

(thousands of barrels daily)

Crude oil and natural gas liquids production

 

Crude Oil

NGL

 

Crude Oil

NGL

 

Crude Oil

NGL

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

United States

 

361

96

 

347

87

 

326

86

 

 

Canada/Other Americas

 

44

6

 

53

6

 

47

8

 

 

Europe

 

147

31

 

171

31

 

173

28

 

 

Africa

 

412

11

 

459

15

 

511

18

 

 

Asia

 

373

26

 

383

27

 

346

29

 

 

Australia/Oceania

 

35

19

 

37

19

 

33

17

 

 

 

Total Consolidated Subsidiaries

 

1,372

189

 

1,450

185

 

1,436

186

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

United States

 

55

2

 

58

2

 

61

3

 

 

Europe

 

4

-

 

2

-

 

3

-

 

 

Asia

 

235

64

 

232

65

 

241

68

 

 

 

Total Equity Companies

 

294

66

 

292

67

 

305

71

 

 

 

 

 

 

 

 

 

 

 

 

 

Total crude oil and natural gas liquids production

 

1,666

255

 

1,742

252

 

1,741

257

 

 

 

 

 

 

 

 

 

 

 

 

 

Bitumen production

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

Canada/Other Americas

 

305

 

 

304

 

 

289

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Synthetic oil production

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

Canada/Other Americas

 

57

 

 

67

 

 

58

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total liquids production

 

2,283

 

 

2,365

 

 

2,345

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(millions of cubic feet daily)

 

Natural gas production available for sale

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

United States

 

2,910

 

 

3,052

 

 

3,116

 

 

 

Canada/Other Americas (1) 

 

218

 

 

239

 

 

261

 

 

 

Europe

 

1,046

 

 

1,093

 

 

1,110

 

 

 

Africa

 

5

 

 

7

 

 

5

 

 

 

Asia

 

906

 

 

927

 

 

1,080

 

 

 

Australia/Oceania

 

1,310

 

 

887

 

 

677

 

 

 

 

Total Consolidated Subsidiaries

 

6,395

 

 

6,205

 

 

6,249

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

United States

 

26

 

 

26

 

 

31

 

 

 

Europe

 

902

 

 

1,080

 

 

1,176

 

 

 

Asia

 

2,888

 

 

2,816

 

 

3,059

 

 

 

 

Total Equity Companies

 

3,816

 

 

3,922

 

 

4,266

 

Total natural gas production available for sale

 

10,211

 

 

10,127

 

 

10,515

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(thousands of oil-equivalent barrels daily)

 

Oil-equivalent production

 

3,985

 

 

4,053

 

 

4,097

 

 

(1)   Other Americas includes natural gas production available for sale for 2017, 2016 and 2015 of 24 million, 22 million, and 21 million cubic feet daily, respectively.

8 


 

B. Production Prices and Production Costs

The table below summarizes average production prices and average production costs by geographic area and by product type for the last three years.

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

 

 

 

 

 

 

United

Other

 

 

 

 

 

Australia/

 

 

 

 

 

 

States

Americas

Europe

 

Africa

 

Asia

Oceania

Total

During 2017

 

(dollars per unit)

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

46.71

 

52.42

 

52.02

 

54.70

 

53.26

 

53.61

 

51.88

 

 

 

NGL, per barrel

 

24.20

 

27.07

 

30.96

 

37.38

 

22.69

 

33.15

 

26.88

 

 

 

Natural gas, per thousand cubic feet

 

2.03

 

2.03

 

5.48

 

1.51

 

2.05

 

4.22

 

3.04

 

 

 

Bitumen, per barrel

 

-

 

29.70

 

-

 

-

 

-

 

-

 

29.70

 

 

 

Synthetic oil, per barrel

 

-

 

52.72

 

-

 

-

 

-

 

-

 

52.72

 

 

Average production costs, per oil-equivalent barrel - total

10.85

 

23.44

 

12.25

 

13.33

 

8.07

 

6.30

 

12.33

 

 

Average production costs, per barrel - bitumen

-

 

21.39

 

-

 

-

 

-

 

-

 

21.39

 

 

Average production costs, per barrel - synthetic oil

-

 

44.21

 

-

 

-

 

-

 

-

 

44.21

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

49.13

 

-

 

47.69

 

-

 

50.27

 

-

 

50.02

 

 

 

NGL, per barrel

 

21.78

 

-

 

-

 

-

 

38.23

 

-

 

37.81

 

 

 

Natural gas, per thousand cubic feet

 

2.42

 

-

 

4.81

 

-

 

4.15

 

-

 

4.30

 

 

Average production costs, per oil-equivalent barrel - total

23.38

 

-

 

7.45

 

-

 

1.18

 

-

 

3.51

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

47.03

 

52.42

 

51.91

 

54.70

 

52.12

 

53.61

 

51.56

 

 

 

NGL, per barrel

 

24.16

 

27.07

 

30.96

 

37.38

 

33.79

 

33.15

 

29.70

 

 

 

Natural gas, per thousand cubic feet

 

2.03

 

2.03

 

5.17

 

1.51

 

3.65

 

4.22

 

3.51

 

 

 

Bitumen, per barrel

 

-

 

29.70

 

-

 

-

 

-

 

-

 

29.70

 

 

 

Synthetic oil, per barrel

 

-

 

52.72

 

-

 

-

 

-

 

-

 

52.72

 

 

Average production costs, per oil-equivalent barrel - total

11.61

 

23.44

 

10.79

 

13.33

 

4.02

 

6.30

 

10.12

 

 

Average production costs, per barrel - bitumen

-

 

21.39

 

-

 

-

 

-

 

-

 

21.39

 

 

Average production costs, per barrel - synthetic oil

-

 

44.21

 

-

 

-

 

-

 

-

 

44.21

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

During 2016

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

36.47

 

39.50

 

40.57

 

42.59

 

41.89

 

43.33

 

40.59

 

 

 

NGL, per barrel

 

16.16

 

18.91

 

22.17

 

26.78

 

17.12

 

23.95

 

18.99

 

 

 

Natural gas, per thousand cubic feet

 

1.43

 

1.71

 

4.26

 

1.14

 

1.56

 

3.46

 

2.25

 

 

 

Bitumen, per barrel

 

-

 

19.30

 

-

 

-

 

-

 

-

 

19.30

 

 

 

Synthetic oil, per barrel

 

-

 

43.03

 

-

 

-

 

-

 

-

 

43.03

 

 

Average production costs, per oil-equivalent barrel - total

10.41

 

21.16

 

12.78

 

12.75

 

6.44

 

7.12

 

11.79

 

 

Average production costs, per barrel - bitumen

-

 

18.25

 

-

 

-

 

-

 

-

 

18.25

 

 

Average production costs, per barrel - synthetic oil

-

 

33.64

 

-

 

-

 

-

 

-

 

33.64

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

38.44

 

-

 

36.13

 

-

 

39.69

 

-

 

39.41

 

 

 

NGL, per barrel

 

14.85

 

-

 

-

 

-

 

25.21

 

-

 

24.87

 

 

 

Natural gas, per thousand cubic feet

 

2.03

 

-

 

4.19

 

-

 

3.59

 

-

 

3.75

 

 

Average production costs, per oil-equivalent barrel - total

22.26

 

-

 

7.92

 

-

 

1.80

 

-

 

4.21

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

36.75

 

39.50

 

40.51

 

42.59

 

41.06

 

43.33

 

40.39

 

 

 

NGL, per barrel

 

16.13

 

18.91

 

22.17

 

26.78

 

22.85

 

23.95

 

20.56

 

 

 

Natural gas, per thousand cubic feet

 

1.44

 

1.71

 

4.22

 

1.14

 

3.09

 

3.46

 

2.83

 

 

 

Bitumen, per barrel

 

-

 

19.30

 

-

 

-

 

-

 

-

 

19.30

 

 

 

Synthetic oil, per barrel

 

-

 

43.03

 

-

 

-

 

-

 

-

 

43.03

 

 

Average production costs, per oil-equivalent barrel - total

11.18

 

21.16

 

11.21

 

12.75

 

3.77

 

7.12

 

9.89

 

 

Average production costs, per barrel - bitumen

-

 

18.25

 

-

 

-

 

-

 

-

 

18.25

 

 

Average production costs, per barrel - synthetic oil

-

 

33.64

 

-

 

-

 

-

 

-

 

33.64

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9 


 

 

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

 

 

 

 

 

 

 

United

Other

 

 

 

 

 

Australia/

 

 

 

 

 

 

States

Americas

Europe

 

Africa

 

Asia

 

Oceania

 

Total

During 2015

 

(dollars per unit)

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

41.87

 

44.30

 

49.04

 

51.01

 

48.30

 

49.56

 

47.75

 

 

 

NGL, per barrel

 

16.96

 

21.91

 

27.50

 

33.41

 

21.14

 

29.75

 

22.16

 

 

 

Natural gas, per thousand cubic feet

 

1.65

 

1.78

 

6.47

 

1.57

 

2.02

 

5.13

 

2.95

 

 

 

Bitumen, per barrel

 

-

 

25.07

 

-

 

-

 

-

 

-

 

25.07

 

 

 

Synthetic oil, per barrel

 

-

 

48.15

 

-

 

-

 

-

 

-

 

48.15

 

 

Average production costs, per oil-equivalent barrel - total

12.50

 

22.68

 

15.86

 

10.31

 

7.71

 

8.86

 

12.97

 

 

Average production costs, per barrel - bitumen

 

-

 

19.20

 

-

 

-

 

-

 

-

 

19.20

 

 

Average production costs, per barrel - synthetic oil

 

-

 

41.83

 

-

 

-

 

-

 

-

 

41.83

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

46.34

 

-

 

46.05

 

-

 

48.44

 

-

 

47.99

 

 

 

NGL, per barrel

 

15.37

 

-

 

-

 

-

 

32.36

 

-

 

31.75

 

 

 

Natural gas, per thousand cubic feet

 

2.05

 

-

 

6.27

 

-

 

5.83

 

-

 

5.92

 

 

Average production costs, per oil-equivalent barrel - total

22.15

 

-

 

7.75

 

-

 

1.41

 

-

 

3.89

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

42.58

 

44.30

 

48.97

 

51.01

 

48.36

 

49.56

 

47.79

 

 

 

NGL, per barrel

 

16.92

 

21.91

 

27.50

 

33.41

 

28.94

 

29.75

 

24.77

 

 

 

Natural gas, per thousand cubic feet

 

1.65

 

1.78

 

6.37

 

1.57

 

4.84

 

5.13

 

4.16

 

 

 

Bitumen, per barrel

 

-

 

25.07

 

-

 

-

 

-

 

-

 

25.07

 

 

 

Synthetic oil, per barrel

 

-

 

48.15

 

-

 

-

 

-

 

-

 

48.15

 

 

Average production costs, per oil-equivalent barrel - total

13.16

 

22.68

 

13.09

 

10.31

 

3.96

 

8.86

 

10.56

 

 

Average production costs, per barrel - bitumen

 

-

 

19.20

 

-

 

-

 

-

 

-

 

19.20

 

 

Average production costs, per barrel - synthetic oil

 

-

 

41.83

 

-

 

-

 

-

 

-

 

41.83

 

Average production prices have been calculated by using sales quantities from the Corporation’s own production as the divisor. Average production costs have been computed by using net production quantities for the divisor. The volumes of crude oil and natural gas liquids (NGL) production used for this computation are shown in the oil and gas production table in section 3.A. The volumes of natural gas used in the calculation are the production volumes of natural gas available for sale and are also shown in section 3.A. The natural gas available for sale volumes are different from those shown in the reserves table in the “Oil and Gas Reserves” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion of the Financial Section of this report due to volumes consumed or flared. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.

10 


 

4. Drilling and Other Exploratory and Development Activities

A. Number of Net Productive and Dry Wells Drilled



 

 

 

 

 

 

2017

 

2016

 

2015

 

 

 

 

 

 

 

 

 

 

Net Productive Exploratory Wells Drilled

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

United States

 

-

 

-

 

-

 

 

Canada/Other Americas

 

5

 

2

 

1

 

 

Europe

 

-

 

1

 

1

 

 

Africa

 

1

 

1

 

1

 

 

Asia

 

-

 

-

 

2

 

 

Australia/Oceania

 

-

 

-

 

1

 

 

 

Total Consolidated Subsidiaries

 

6

 

4

 

6

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

United States

 

-

 

-

 

-

 

 

Europe

 

-

 

1

 

1

 

 

Africa

 

-

 

-

 

-

 

 

Asia

 

-

 

-

 

-

 

 

 

Total Equity Companies

 

-

 

1

 

1

Total productive exploratory wells drilled

 

6

 

5

 

7

 

 

 

 

 

 

 

 

 

 

Net Dry Exploratory Wells Drilled

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

United States

 

-

 

-

 

1

 

 

Canada/Other Americas

 

-

 

1

 

-

 

 

Europe

 

-

 

-

 

2

 

 

Africa

 

2

 

1

 

-

 

 

Asia

 

-

 

-

 

-

 

 

Australia/Oceania

 

-

 

-

 

-

 

 

 

Total Consolidated Subsidiaries

 

2

 

2

 

3

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

United States

 

-

 

-

 

1

 

 

Europe

 

-

 

-

 

1

 

 

Africa

 

-

 

-

 

-

 

 

Asia

 

1

 

-

 

-

 

 

 

Total Equity Companies

 

1

 

-

 

2

Total dry exploratory wells drilled

 

3

 

2

 

5

11 


 

 

 

 

 

 

2017

 

2016

 

2015

 

 

 

 

 

 

 

 

 

 

Net Productive Development Wells Drilled

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

United States

 

300

 

335

 

692

 

 

Canada/Other Americas

 

12

 

13

 

53

 

 

Europe

 

6

 

9

 

10

 

 

Africa

 

6

 

7

 

23

 

 

Asia

 

15

 

13

 

14

 

 

Australia/Oceania

 

1

 

-

 

4

 

 

 

Total Consolidated Subsidiaries

 

340

 

377

 

796

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

United States

 

154

 

121

 

390

 

 

Europe

 

1

 

2

 

1

 

 

Africa

 

-

 

-

 

-

 

 

Asia

 

3

 

3

 

2

 

 

 

Total Equity Companies

 

158

 

126

 

393

Total productive development wells drilled

 

498

 

503

 

1,189

 

 

 

 

 

 

 

 

 

 

Net Dry Development Wells Drilled

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

United States

 

4

 

2

 

5

 

 

Canada/Other Americas

 

-

 

-

 

-

 

 

Europe

 

1

 

2

 

3

 

 

Africa

 

-

 

-

 

1

 

 

Asia

 

-

 

-

 

-

 

 

Australia/Oceania

 

-

 

-

 

-

 

 

 

Total Consolidated Subsidiaries

 

5

 

4

 

9

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

United States

 

-

 

-

 

-

 

 

Europe

 

-

 

-

 

-

 

 

Africa

 

-

 

-

 

-

 

 

Asia

 

-

 

-

 

-

 

 

 

Total Equity Companies

 

-

 

-

 

-

Total dry development wells drilled

 

5

 

4

 

9

 

 

 

 

 

 

 

 

 

 

 

Total number of net wells drilled

 

512

 

514

 

1,210

12 


 

B. Exploratory and Development Activities Regarding Oil and Gas Resources Extracted by Mining Technologies

Syncrude Operations. Syncrude is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen, and then upgrade it to produce a high-quality, light (32 degrees API), sweet, synthetic crude oil. Imperial Oil Limited is the owner of a 25 percent interest in the joint venture. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited. In 2017, the company’s share of net production of synthetic crude oil was about 57 thousand barrels per day and share of net acreage was about 63 thousand acres in the Athabasca oil sands deposit.

Kearl Operations. Kearl is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen. Imperial Oil Limited holds a 70.96 percent interest in the joint venture and ExxonMobil Canada Properties holds the other 29.04 percent. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited and a 100 percent interest in ExxonMobil Canada Properties. Kearl is comprised of six oil sands leases covering about 49 thousand acres in the Athabasca oil sands deposit.

Kearl is located approximately 40 miles north of Fort McMurray, Alberta, Canada. Bitumen is extracted from oil sands produced from open-pit mining operations, and processed through bitumen extraction and froth treatment trains. The product, a blend of bitumen and diluent, is shipped to our refineries and to other third parties. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation by pipeline and rail. During 2017, average net production at Kearl was about 174 thousand barrels per day.

 

5. Present Activities

A. Wells Drilling

 

 

 

 

 

Year-End 2017

 

Year-End 2016

 

 

 

 

Gross

 

Net

 

Gross

 

Net

Wells Drilling

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

United States

820

 

334

 

760

 

302

 

 

Canada/Other Americas

30

 

22

 

22

 

17

 

 

Europe

12

 

2

 

12

 

3

 

 

Africa

10

 

2

 

30

 

7

 

 

Asia

58

 

15

 

38

 

11

 

 

Australia/Oceania

3

 

1

 

4

 

1

 

 

 

Total Consolidated Subsidiaries

933

 

376

 

866

 

341

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

10

 

1

 

22

 

3

 

 

Europe

8

 

3

 

9

 

4

 

 

Asia

14

 

4

 

7

 

2

 

 

 

Total Equity Companies

32

 

8

 

38

 

9

Total gross and net wells drilling

965

 

384

 

904

 

350

B. Review of Principal Ongoing Activities

UNITED STATES

ExxonMobil’s year-end 2017 acreage holdings totaled 12.8 million net acres, of which 0.9 million net acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska.

During the year, 444.9 net development wells were completed in the inland lower 48 states. Development activities focused on liquids-rich opportunities in the onshore U.S., primarily in the Permian Basin of West Texas and New Mexico and the Bakken oil play in North Dakota. In addition, gas development activities continued in the Marcellus Shale of Pennsylvania and West Virginia, the Utica Shale of Ohio  and the Haynesville Shale of East Texas and Louisiana. In 2017, ExxonMobil acquired a number of oil and gas properties in the Permian Basin.

ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2017 was 0.8 million acres. A total of 2.3 net development wells were completed during the year.

Participation in Alaska production and development continued with a total of 10.9 net development wells completed.

13 


 

CANADA / OTHER AMERICAS  

Canada

Oil and Gas Operations:  ExxonMobil’s year-end 2017 acreage holdings totaled 6.5 million net acres, of which 3.2 million net acres were offshore. A total of 10.8 net development wells were completed during the year. The Hebron project started up in 2017.

In Situ Bitumen Operations:  ExxonMobil’s year-end 2017 in situ bitumen acreage holdings totaled 0.7 million net onshore acres.  

Argentina

ExxonMobil’s net acreage totaled 0.3 million onshore acres at year-end 2017, and there were 4.0 net exploration and development wells completed during the year.

Guyana

ExxonMobil’s net acreage totaled 5.2 million offshore acres at year-end 2017, and there were 2.3 net exploration wells completed during the year. The Liza Phase 1 project was funded in 2017.

EUROPE

Germany

A total of 2.8 million net onshore acres were held by ExxonMobil at year-end 2017, with 1.3 net development wells completed during the year.

Netherlands

ExxonMobil’s net interest in licenses totaled approximately 1.5 million acres at year-end 2017, of which 1.1 million acres were onshore. A total of 1.3 net exploration and development wells were completed during the year.

Norway

ExxonMobil’s net interest in licenses at year-end 2017 totaled approximately 0.1 million acres, all offshore. A total of 3.9 net development wells were completed during the year. In 2017, ExxonMobil divested approximately 81 thousand net operated acres in Norway.

United Kingdom

ExxonMobil’s net interest in licenses at year-end 2017 totaled approximately 0.6 million acres, all offshore. A total of 1.2 net exploration and development wells were completed during the year.  The Penguins Redevelopment project was funded in 2017.  

AFRICA

Angola

ExxonMobil’s net acreage totaled 0.2 million offshore acres at year-end 2017, with 5.9 net development wells completed during the year. On Block 32, development activities continued on the Kaombo Split Hub project.  

Chad

ExxonMobil’s net year-end 2017 acreage holdings consisted of 46 thousand onshore acres.

Equatorial Guinea

ExxonMobil’s acreage totaled 0.3 million net offshore acres at year-end 2017, with 2.4 net exploration wells completed during the year.  

Mozambique

ExxonMobil’s net acreage totaled approximately 0.1 million offshore acres at year-end 2017. ExxonMobil acquired an interest in Area 4 offshore Mozambique in December 2017. The Coral South Floating LNG project was funded in 2017.

Nigeria

ExxonMobil’s net acreage totaled 1.1 million offshore acres at year-end 2017, with 0.8 net development wells completed during the year.

14 


 

ASIA

Azerbaijan

At year-end 2017, ExxonMobil’s net acreage totaled 9 thousand offshore acres. A total of 1.3 net development wells were completed during the year.  

Indonesia

At year-end 2017, ExxonMobil had 0.1 million net acres onshore. In 2017, ExxonMobil relinquished approximately 0.4 million net acres offshore.

Iraq

At year-end 2017, ExxonMobil’s onshore acreage was 0.1 million net acres. A total of 4.5 net development wells were completed at the West Qurna Phase I oil field during the year. Oil field rehabilitation activities continued during 2017 and across the life of this project will include drilling of new wells, working over of existing wells, and optimization and debottlenecking of existing facilities. In the Kurdistan Region of Iraq, ExxonMobil continued exploration activities.

Kazakhstan

ExxonMobil’s net acreage totaled 0.1 million acres onshore and 0.2 million acres offshore at year-end 2017. A total of 4.3 net development wells were completed during 2017. Development activities continued on the Tengiz Expansion project.

Malaysia

ExxonMobil’s interests in production sharing contracts covered 2.5 million net acres offshore at year-end 2017. During the year, a total of 1.5 net development wells were completed. ExxonMobil acquired deepwater acreage offshore Sabah.

Qatar

Through our joint ventures with Qatar Petroleum, ExxonMobil’s net acreage totaled 65 thousand acres offshore at year-end 2017. ExxonMobil participated in 62.2 million tonnes per year gross liquefied natural gas capacity and 2.0 billion cubic feet per day of flowing gas capacity at year end. Development activities continued on the Barzan project in 2017.

Republic of Yemen

ExxonMobil’s net acreage in the Republic of Yemen production sharing areas totaled 10 thousand acres onshore at year-end 2017.

Russia

ExxonMobil’s net acreage holdings in Sakhalin at year-end 2017 were 85 thousand acres, all offshore. A total of 2.1 net exploration and development wells were completed. The Odoptu Stage 2 project started up in 2017.

At year-end 2017, ExxonMobil’s net acreage in the Rosneft joint venture agreements for the Kara, Laptev, Chukchi and Black Seas was 63.6 million acres, all offshore. ExxonMobil and Rosneft formed a joint venture to evaluate the development of tight-oil reserves in western Siberia in 2013. Refer to the relevant portion of “Note 7: Equity Company Information” of the Financial Section of this report for additional information on the Corporation’s participation in Rosneft joint venture activities.

Thailand

ExxonMobil’s net onshore acreage in Thailand concessions totaled 21 thousand acres at year-end 2017.

United Arab Emirates

ExxonMobil’s net acreage in the Abu Dhabi offshore Upper Zakum oil concession was 81 thousand acres at year-end 2017. A total of 5.3 net development wells were completed. During 2017, development activities continued on the Upper Zakum 750 project, and agreements were signed for the Upper Zakum 1MBD (million barrels per day) project, including a 10-year extension to 2051 for the Upper Zakum concession.

 

 

15 


 

AUSTRALIA / OCEANIA

Australia

ExxonMobil’s year-end 2017 acreage holdings totaled 2.0 million net offshore acres. The Gas Conditioning Plant at Longford started up in 2017.

The third train of the co-venturer-operated Gorgon Jansz liquefied natural gas (LNG) project started up in 2017. The project consists of a subsea infrastructure for offshore production and transportation of the gas, a 15.6 million tonnes per year LNG facility and a 280 million cubic feet per day domestic gas plant located on Barrow Island, Western Australia.

Papua New Guinea

A total of 10.1 million net acres were held by ExxonMobil at year-end 2017, of which 5.4 million net acres were offshore. A total of 0.7 net exploration and development wells were completed during the year. The Papua New Guinea (PNG) LNG integrated development includes gas production and processing facilities in the southern PNG Highlands, onshore and offshore pipelines, and a 6.9 million tonnes per year LNG facility near Port Moresby. In 2017, ExxonMobil acquired InterOil Corporation (IOC), an exploration and production business focused on Papua New Guinea.

WORLDWIDE EXPLORATION

At year-end 2017, exploration activities were under way in several areas in which ExxonMobil has no established production operations and thus are not included above. A total of 30.1 million net acres were held at year-end 2017 in these countries.

 

6. Delivery Commitments

ExxonMobil sells crude oil and natural gas from its producing operations under a variety of contractual obligations, some of which may specify the delivery of a fixed and determinable quantity for periods longer than one year. ExxonMobil also enters into natural gas sales contracts where the source of the natural gas used to fulfill the contract can be a combination of our own production and the spot market. Worldwide, we are contractually committed to deliver approximately 57 million barrels of oil and 2,400 billion cubic feet of natural gas for the period from 2018 through 2020. We expect to fulfill the majority of these delivery commitments with production from our proved developed reserves. Any remaining commitments will be fulfilled with production from our proved undeveloped reserves and spot market purchases as necessary.

16 


 

7. Oil and Gas Properties, Wells, Operations and Acreage

A. Gross and Net Productive Wells



 

 

 

 

 

Year-End 2017

 

Year-End 2016

 

 

 

 

Oil

Gas

 

Oil

Gas

 

 

 

 

Gross

Net

Gross

Net

 

Gross

Net

Gross

Net

Gross and Net Productive Wells

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

United States

20,679

8,366

27,700

15,979

 

20,470

8,037

32,949

19,873

 

 

Canada/Other Americas

4,877

4,618

4,273

1,646

 

5,024

4,767

4,362

1,668

 

 

Europe

1,016

267

664

268

 

1,130

323

641

253

 

 

Africa

1,222

474

15

6

 

1,268